The present invention relates to a process for increasing the permeability of a subterranean formation which is at least partially plugged with a polymer accumulation thereby restoring the injectivity of a well penetrating the subterranean formation, and more particularly, to such a process wherein the polymer accumulation is present in the well bore, at the well bore face and/or in the near well bore environment of the subterranean formation and an aqueous treating fluid comprising hydrogen peroxide and a mutual solvent is injected via the well and into the near well bore environment to contact, degrade and disperse the polymer accumulation.
Hydrocarbons are conventionally produced from a subterranean hydrocarbon-bearing formation to the surface via a well penetrating and in fluid communication with the formation. Usually a plurality of wells are drilled into fluid communication with a subterranean hydrocarbon-bearing formation to effectively produce hydrocarbons from a particular subterranean reservoir. Approximately 20 to 30% of the volume of hydrocarbons originally present within a given reservoir in a subterranean formation can be produced by the natural pressure of the formation, i.e., by primary production. Thereafter, additional quantities of hydrocarbons can be produced from most subterranean formations by means of secondary recovery processes, such as water flooding and steam flooding. To accomplish secondary recovery of hydrocarbons present in a subterranean formation, one or more wells are converted to or are drilled as injection wells. A drive fluid, such as water or steam, is injected into the subterranean formation via the injection wells to drive hydrocarbons present in the formation to one or more wells which are designated as production wells. Hydrocarbons are produced to the surface from the designated production wells by conventional production equipment and practices. A successful secondary recovery process may result in the recovery of about 30 to 50% of the original hydrocarbons in place in a subterranean formation.
Tertiary recovery processes have been developed to produce additional quantities of hydrocarbons from subterranean hydrocarbon-bearing formations. Such tertiary recovery processes include the addition of a surfactant and/or a polymer to a drive fluid, such as water. A surfactant reduces the interfacial tension between formation hydrocarbons and reservoir rock, whereas a polymer, such as a polyacrylamide or a polysaccharide, increases the viscosity of the drive fluid to substantially reduce fingering or channeling of the drive fluid through the formation so as to produce a more uniform injection profile which results in increased hydrocarbon recovery.
Polymers used in secondary or tertiary recovery processes often accumulate in the well bore, at the well bore face, and/or in the near well bore environment of a subterranean formation surrounding an injection well over the period of time during which injection of a drive fluid containing a polymer occurs. Where a brine which is produced from a subterranean formation is used to formulate the drive fluid, that portion of hydrocarbon which is not removed from the brine by conventional surface treatment, i.e., hydrocarbon carryover, and the total dissolved solids content of the brine can be filtered out of the injected brine by the accumulated polymer in the well bore, at the well bore face and/or in the near well bore environment surrounding the injection well. Scales, such as calcium carbonate and iron carbonate, as well as naturally occurring algae and formation fines can also be incorporated in the accumulated polymer at the well bore face and/or in the near well bore environment surrounding an injection well. The resultant accumulation of polymer at the well bore face and/or in the near-injection well bore environment may be interbedded with scale, hydrocarbons, crude oil, algae, and/or miscellaneous formation fines. This accumulated polymer can reduce the permeability of a subterranean formation significantly reducing the injectivity of a drive fluid into a subterranean formation via an injection well, and accordingly, significantly reducing the volume of hydrocarbon produced by a secondary or tertiary recovery process. It is suspected that crosslinking of injected polymer by ions, such as Ca.sup.++ and Mg.sup.++, present in injection water, well tubulars, and formation rock, results in polymer accumulation. Large accumulations of polymer are visually detectable as a gel-like material in backflowed fluids from injection wells. Smaller accumulations of polymer, which may be invisible to the eye, also excessively reduce permeability in the rock matrix near the well bore. The accumulation of a discrete number of extremely high molecular weight polymer molecules can substantially plug small pores in the formation and greatly reduce permeability therein. The period of time before loss of drive fluid injectivity due to polymer accumulation in the well bore, at the well bore face, and/or in the near well bore environment surrounding an injection well occurs is dependent upon formation porosity, ionic characteristics of the formation, the molecular weight of and concentration of the polymer in a drive fluid, and the velocity of the injection rate of a drive fluid. Significant loss of injectivity, e.g., 25% to 75%, may occur within one year after commencing injection of a drive fluid into a subterranean formation.
In order to restore the permeability of a subterranean formation surrounding an injection well which has been reduced by polymer accumulation in the near well bore environment, a heated aqueous solution having an acid, such as hydrochloric acid, chlorine dioxide or equivalent acids, dissolved therein has been injected via the injection well and into the formation to dissolve and disperse the polymer accumulation. However, such treatments are relatively expensive and are corrosive to surface and well bore tubulars. Accordingly, a need exists for a process for restoring the injectivity of an injection well in fluid communication with a subterranean formation, the permeability of the near injection well bore environment being reduced by polymer accumulation, which is relatively inexpensive and effective.
Accordingly, it is an object of the present invention to provide a process for restoring the injectivity of a well penetrating a subterranean formation and having a polymer accumulation in the well bore, at the well bore face, and/or in near injection well bore portion of the subterranean formation by effectively increasing the permeability of a subterranean formation.
It is another object of the present invention to provide such a process for restoring the injectivity of a well in fluid communication with a subterranean formation which is relatively inexpensive.